The present disclosure relates to earth penetrating drilling equipment and, more particularly, to physically marking drilling equipment and drilling equipment assemblies such that tandem drilling components may be intelligently coupled.
Wellbores are formed in subterranean formations for various purposes including, for example, the extraction of oil and gas and the extraction of geothermal heat. Such wellbores are typically formed using one or more drill bits, such as fixed-cutter bits (i.e., drag bits), roller-cone bits (i.e., rock bits), diamond-impregnated bits, and hybrid bits, which may include, for example, both fixed cutters and rolling cutters. The drill bit is coupled either directly or indirectly to an end of a drill string, which encompasses a series of elongated tubular segments connected end-to-end that extends into the wellbore from a surface location. Various tools and components, including the drill bit, are often arranged or otherwise coupled at the distal end of the drill string at the bottom of the wellbore. This assembly of tools and components is commonly referred to as a bottom hole assembly (BHA).
In order to form the wellbore, the drill bit is rotated and its associated cutters or abrasive structures cut, crush, shear, and/or abrade away the formation materials, thereby facilitating the advancement of the drill bit into subterranean formations. In some cases, the drill bit is rotated within the wellbore by rotating the drill string from the surface while drilling fluid is pumped from the surface to the drill bit. The drilling fluid exits the drill string at the drill bit and serves to cool the drill bit and flush drilling particulates back to the surface. In other cases, however, the drill bit may be rotated using a downhole motor (e.g., a mud motor) powered by the drilling fluid pumped from the surface.
To enlarge the diameter of the wellbore, a reamer device (also referred to as a hole opening device or a hole opener) may be used in conjunction with the drill bit as part of the BHA. The reamer is typically axially-offset uphole from the drill bit along the length of the BHA and exhibits a diameter greater than that of the drill bit. While typically arranged concentric with the drill bit, some reamers can be radially offset from the drill bit. Reamers can also be of fixed or variable geometry. In operation, the drill bit operates as a pilot bit to form a pilot bore in the subterranean formation, and the reamer follows the drill bit through the pilot bore to enlarge the diameter of the wellbore as the BHA advances into the formation.
Each of these drilling components (i.e., the drill bit and the reamer) can be designed to have as little cutting and mass imbalance forces as possible, since such imbalances can result in inefficient drilling and unwanted vibration propagating through the drill string during drilling. These imbalance forces include a component force that urges each drilling component laterally during drilling, thereby resulting in lateral vibrations. While the design of each drilling component endeavors to minimize these unbalance forces, such imbalances are present in practically all drill bits and reamers. When such drilling components are used in tandem along the BHA, their respective unbalanced forces can cooperatively amplify the vibrations in the drill string, thereby further reducing drilling efficiencies and potentially increasing equipment damage.